Well drilling and servicing fluids with magnesia bridging solids and methods of drilling, completing and working over a well therewith

ABSTRACT

The invention provides well drilling and servicing fluids, and methods of drilling, completing, or working over a well therewith, preferred fluids comprise an aqueous liquid, a water soluble polymer viscosifier (preferably xanthan gum), a polymeric fluid loss control additive (preferably a partially depolymerized partially crosslinked hydroxyalkyl ether derivative of starch or a hydroxyalkyl ether derivative of a partially crosslinked and partially depolymerized starch), and as a bridging agent a particulate magnesia that has an Activity Index greater than about 800 seconds, preferably from about 800 seconds to about 3000 seconds.

BACKGROUND OF THE INVENTION

The present invention relates to clay-free aqueous well drilling andservicing fluids, methods of preparation thereof, and methods ofdrilling or servicing a well therewith.

The use of fluids for conducting various operations in the boreholes ofoil and gas wells which contact a hydrocarbon-containing subterraneanformation are well known. Thus, drill-in fluids are utilized wheninitially drilling into potential hydrocarbon producing formations.Completion fluids are utilized when conducting various completionoperations in the hydrocarbon-containing formations. Workover fluids areutilized when conducting workover operations of previously completedwells.

It is important that the fluids which contact hydrocarbon-containingformations are formulated such that there is a minimum penetration offluid, both the aqueous phase and the solid phase, into the formation.Thus, the present state-of-the-art fluids generally comprise a “watersoluble” polymer, preferably a biopolymer such as xanthan gum orscleroglucan gum, starch derivatives for fluid loss control, and watersoluble or acid soluble bridging agents to form a thin filter cake whichforms a protective seal of the formation. See for example the followingU.S. Patents, incorporated herein by reference: Mondshine U.S. Pat. No.4,620,596; Dobson, Jr. et al. U.S. Pat. No. 4,822,500; Dobson, Jr. etal. U.S. Pat. No. 5,629,271; Dobson, Jr. et al. U.S. Pat. No. 5,641,728;Dobson, Jr. et al. U.S. Pat. No. 5,728,652; and Dobson, Jr. et al. U.S.Pat. No. 5,804,535. A recent development is a biopolymer-free fluidwhich utilizes a unique amylopectin starch derivative for both viscositydevelopment and fluid loss control as set forth in Dobson, Jr. et al.U.S. Pat. No. 6,391,830.

After the well has been drilled and completed, it is necessary to removethe filter cake from the surface of the formation allowing thehydrocarbons therein to flow to the wellbore for production. This isgenerally aided by contacting the filter cake with various washes/soaksolutions in which the components of the filter cake are soluble, mostgenerally acidic aqueous fluids. See, for example, the following U.S.patents, incorporated herein by reference: Mondshine et al. U.S. Pat.No. 5,238,065; Dobson, Jr. et al. U.S. Pat. No. 5,607,905; Dobson, Jr.et al. U.S. Pat. No. 5,783,527; and Dobson, Jr. et al. U.S. Pat. No.5,783,526.

As indicated in Mondshine U.S. Pat. No. 4,620,596, sparingly solubleborates have been utilized as bridging agents in well drilling andservicing fluids. However, one problem with their use inbiopolymer-containing fluids is the crosslinking of the biopolymers thatoccurs when the borate anion reacts with the biopolymers. Thus, there isa need for another bridging agent that is sparingly soluble inwater/aqueous systems and is soluble in acidic solutions.

Powdered magnesium oxide is utilized in the art as an alkalinity controladditive for biopolymer-containing fluids as exemplified by the U.S.patents referenced hereinbefore.

The magnesium oxide as referenced in Dobson, Jr. et al. U.S. Pat. No.5,514,644, incorporated herein by reference, has an Activity Index lessthan about 100 seconds, most preferably less than about 50 seconds.

We have investigated the use of particulate, sized magnesium oxide as abridging agent in biopolymer-containing fluids and found that theincreased concentrations of the magnesium oxide needed for proper filtercake development (i.e., bridging) generates a gelatinous mass afterthermal aging of the fluids.

The present invention pertain to stable well drilling and servicingfluids which provide a filter cake that is partially water soluble andsubstantially acid soluble for improved removal from the sides of theborehole/face of the hydrocarbon-containing formations on which thefilter cake is deposited.

SUMMARY OF THE INVENTION

We have now found that calcined (so-called “deadburned”) magnesia whichhas an Activity Index greater than about 800 seconds providesbiopolymer-containing well drilling and servicing fluids which do notgel on thermal aging at temperatures at which the biopolymer does notdecompose and which utilizes the particulate, sized magnesia particlesas a bridging agent to form the required thin filter cake to limit fluidinvasion into the hydrocarbon-containing formation contacted by thefluid.

The present invention provides a stable water soluble polymer-containingwell drilling and servicing fluid which utilizes as a bridging agentparticulate, sized calcined magnesia which has an Activity Index greaterthan about 800 seconds.

The present invention provides a method of drilling a well wherein thereis circulated within the wellbore being drilled as drilling proceeds awater base drilling fluid containing as a bridging agent particulate,sized calcined magnesia which has an Activity Index greater than about800 seconds.

The present invention further provides a process of completing orworking over a well wherein a subterranean formation is contacted withan aqueous fluid wherein the fluid contains a bridging agent comprisinga particulate, sized magnesia which has an Activity Index greater thanabout 800 seconds.

Other objects, features and embodiments of the invention are disclosedin the following description of the invention and appended claims.

While the invention is susceptible to various modifications andalternative forms, specific embodiments thereof will hereinafter bedescribed in detail and shown by way of example. It should beunderstood, however, that it is not intended to limit the invention tothe particular forms disclosed, but, on the contrary, the invention isto cover all modifications and alternatives falling within the spiritand scope of the invention as expressed in the appended claims.

The compositions can comprise, consist essentially of, or consist of thestated materials. The method can comprise, consist essentially of, orconsist of the stated steps with the stated materials.

DETAILED DESCRIPTION OF THE INVENTION

The present invention is based on the principle that particulate, sizedcalcined magnesia which has an Activity Index greater than about 800seconds can be utilized as a partially water soluble, completely acidsoluble bridging agent in well drilling and servicing fluids(hereinafter sometimes referred to as “WDSF”).

The Activity Index of magnesia is obtained using the following apparatusand test procedures.

The rate at which magnesium oxide reacts with a dilute solution ofacetic acid is used as a measure of activity. An excess of magnesia isused so that at the end point of the reaction, the solution goes fromacidic to basic and is detected by a color change employingphenolphthalein indicator.

Apparatus and Reagents:

Acetic acid solution 1.00±0.01N, standardized

Phenolphthalein soln. (1% solution in ethanol)

Waring blender, 2 speed with 32 oz. glass container

Balance with sensitivity of 0.01 gm

Stopwatch

Thermometer

Graduated cylinders, 100 ml and 500 ml

Procedure

-   1. Prior to the test, the water and the acetic acid solution should    be brought to a temperature of 25±1 C.-   2. Weigh a 5.00±0.02 grams aliquot of the magnesia sample.-   3. Measure out 300 ml of water in a graduated cylinder and add it to    the blender.-   4. Carefully hold a thermometer in the blender and run blender until    the temperature of the water is 28° C. Turn off the blender.-   5. Add 5-10 drops of phenolphthalein indicator solution.-   6. Add the magnesia sample and immediately start the blender on low    speed.-   7. Count ten seconds from the start of the blender and add 100 ml of    the 1.00N acetic acid solution. The stopwatch is started as the acid    is being added.-   8. Stop the timer when the solution turns to a definite pink color.    Record the reaction time in seconds as the activity index of the    magnesia.-   9. Note: Add three to five additional drops of indicator solution to    the blender every 30 seconds until the color change has taken place.

Magnesia having an Activity Index less than about 800 seconds is toowater soluble producing biopolymer-containing fluids which becomegelatinous on heating.

The WDSF of the invention comprise one or more polymerviscosifier/suspension agents, one or more polymeric fluid loss controlagents, and the magnesia bridging agent dispersed in an aqueous liquid.

The preferred polymer viscosifier is a biopolymer (microbialpolysaccharide). The term “biopolymer” is intended to mean an excellularpolysaccharide of high molecular weight, in excess of about 500,000,produced by fermentation of a carbohydrate source by the action ofbacteria or fungi.

Representative microorganisms are the genus Xanthomonas, Pseudomonas,Agrobacterium, Arthrobacter, Rhizobium, Alcaligenes, Beijerincka, andSclerotium. A scleroglucan type polysaccharide produced bymicroorganisms such as NCIB 11592 and NCIB 11883 is commerciallyavailable from Degussa.

The preferred biopolymer viscosifier useful in the practice of thisinvention is preferably a xanthomonas gum (xanthan gum). Xanthomonas gumis available commercially from Rhodia under the tradename VISULTRA. Itis a widely used viscosifier and suspending agent in a variety offluids. Xanthomonas gum can be made by the fermentation of carbohydratewith bacteria of the genus Xanthomonas. Representative of these bacteriaare Xanthomonas campestris, Xanthomonas phaseoli, Xanthomonasmulvacearn, Xanthomonas carotoe, Xanthomonas traslucens, Xanthomonashederae, and Xanthomonas papavericoli. The gum produced by the bacteriaXanthomonas campestris is preferred for the purpose of this invention.The fermentation usually involves inoculating a fermentable brothcontaining a carbohydrate, various minerals and a nitrogen yieldingcompound. A number of modifications in the fermentation procedure andsubsequent processing are commercially used. Due to the variety offermentation techniques and difference in processing operationsubsequent to fermentation, different production lots of xanthomonas gumwill have somewhat different solubility and viscosity properties.Xanthomonas gums useful in the practice of the present invention arerelatively hydratable xanthomonas gums.

Xanthan gum is a polymer containing mannose, glucose, glucuronic acidsalts such as potassium glucuronate, sodium glucuronate, or the like,and acetyl radicals. Other Xanthomonas bacteria have been found whichproduce the hydrophilic gum and any of the xanthan gums and theirderivatives can be used in this invention. Xanthan gum is a highmolecular weight linear polysaccharide that is readily soluble in waterto form a viscous fluid.

Other biopolymers prepared by the action of other bacteria, or fungi, onappropriate fermentation mediums may be used in the fluids of thepresent invention provided that they impart the desired thermally stableTheological characteristics thereto. This can be readily determined byone skilled in the art in accordance with the teachings of thisspecification.

Polymeric fluid loss control additives used in well drilling andservicing fluids are so-called water soluble polymers includingpregelatinized starch, starch derivatives, cellulose derivatives,lignocellulose derivatives, and synthetic polymers.

Representative starch derivatives include: hydroxyalkyl starches such ashydroxyethyl starch, hydroxypropyl starch, hydroxypropyl carboxymethylstarch, the slightly crosslinked derivatives thereof, and the like;carboxymethyl starch and the slightly crosslinked derivatives thereof;cationic starches such as the tertiary aminoalkyl ether derivatives ofstarch, the slightly crosslinked derivatives thereof, and the like.Representative cellulose derivatives include low molecular weightcarboxymethyl cellulose, and the like. Representative lignocellulosederivatives include the alkali metal and alkaline earth metal salts oflignosulfonic acid and graft copolymers thereof. Representativesynthetic polymers include vinyl sulfonate copolymers, and polymerscontaining other sulfonate monomers.

The preferred polymeric fluid loss control additives used in theinvention are the starch ether derivatives such as hydroxyethyl starch,hydroxypropyl starch, dihydroxypropyl starch, carboxymethyl starch,hydroxyalkyl carboxymethyl starch, and cationic starches, and theslightly crosslinked derivatives of these starch ethers, most preferablythe hydroxypropyl ether derivative of starch and the slightlycrosslinked derivatives thereof.

Most preferably the polymeric fluid loss control additive is a starchether derivative which has been slightly crosslinked, such as withepichlorohydrin, phosphorous oxychloride, soluble trimetaphosphates,linear dicarboxylic acid anhydrides, N,N¹-methylenebisacrylamide, andother reagents containing two or more functional groups which are ableto react with at least two hydroxyl groups. The preferred crosslinkingreagent is epichlorohydrin. Generally, the treatment level is from about0.005% to about 0.1% of the starch to give a low degree of crosslinkingof about one crosslink per 200 to 1000 anhydroglucose units. Thecrosslinking may be undertaken before or after the starch isderivatized. Additionally, the starch may be modified by acid or enzymehydrolysis or oxidation, to provide a lower molecular weight, partiallydepolyermized, starch polymer for derivatization. Alternatively, thestarch ether derivative may be modified by acid hydrolysis or oxidationto provide a lower molecular weight starch ether derivative. The bookentitled “Modified Starches: Properties and Uses,” by O. B. Wurzburg,1986 (CRC Press, Inc., Boca Raton, Fla., U.S.A.) is an excellent sourcefor information in the preparation of starch derivatives.

Still most preferably, the polymeric fluid loss additive is a starchderivative selected from the group consisting of (1) a crosslinked etherderivative of a partially hydrolyzed starch, (2) a partiallydepolymerized, crosslinked ether derivative of starch, and (3) mixturesthereof, as set forth in Dobson, Jr. et al. U.S. Pat. No. 5,641,728,incorporated herein by reference.

In case (1) the starch is partially depolymerized prior to crosslinkingand derivatizing the starch, whereas in the latter case (2) the starchis first crosslinked and derivatized prior to partially depolymerizingthe starch derivative. In either case, the molecular weight of thecrosslinked starch derivative is decreased by the partialdepolymerization of the starch polymer. As used throughout thisspecification and claims, the terms “partially depolymerized starchderivative,” and “hydrolyzed starch derivative” and the like areintended to mean the starch derivatives prepared by either case (I) orcase (2).

In case (1), it is preferred that the starch be hydrolyzed ordepolymerized to the extent that the viscosity of an aqueous dispersionof the starch is reduced about 25% to about 92%, preferably about 50% toabout 90%, prior to crosslinking and derivatizing the starch. In case(2), it is preferred that the crosslinked starch derivative behydrolyzed or depolymerized to the extent that the viscosity of a waterdispersion of the starch derivative at a concentration of 60 kg/m³ isreduced about 15% to about 50%, preferably about 20% to about 40%.

Patents which disclose oxidative processes for partially depolymerizingstarch derivatives and/or starches include the following, incorporatedherein by reference: U.S. Pat. No. 3,975,206 (Lotzgesell et al.); U.S.Pat. No. 3,935,187 (Speakman); U.S. Pat. No. 3,655,644 (Durand). Patentswhich disclose acidic processes for partially depolymerizing starchderivatives and/or starches include the following, incorporated hereinby reference: U.S. Pat. No. 3,175,928 (Lancaster et al.); U.S. Pat. No.3,073,724 (Rankin et al.). Reference information on the acidmodification of starches is presented in “Starch: Chemistry andTechnology” 2nd Edition, 1984, Roy L. Whistler, James N. Bemiller andEugene F. Paschall, editors, Chapter XVII, pp. 529-541, “Acid-ModifiedStarch: Production and Uses.”

The partially depolymerized or hydrolyzed starch in case (1) or thestarch in case (2) is crosslinked with a compound the molecules of whichare capable of reacting with two or more hydroxyl groups. Representativecrosslinking materials are epichlorohydrin and other epihalohydrins,formaldehyde, phosphorous oxychloride, trimetaphosphate, dialdehydes,vinyl sulfone, diepoxides, diisocyanates, bis(hydroxymethyl) ethyleneurea, and the like. The preferred crosslinking compound isepichlorohydrin. Crosslinking of the starch (or hydrolyzed starch)results in an increase in the molecular weight of the starch and anincrease in the viscosity of aqueous dispersions of the starch.

The reaction conditions used in making crosslinked starches vary widelydepending upon the specific bi-or polyfunctional reagent used for thecrosslinking. In general, most of the reactions are run on aqueoussuspensions of starch at temperatures ranging from room temperature upto about 50° C. Often an alkali such as sodium hydroxide is used topromote reaction. The reactions are normally run under neutral to fairlyalkaline conditions, but below the level which will peptize or swell thestarch. If the crosslinking reaction is run in an aqueous suspension ofstarch, when the desired level of crosslinking (usually as measured bysome type of viscosity or rheology test) is reached, the starchsuspension is neutralized and the starch is filtered and washed toremove salts, any unreacted reagent, and other impurities produced byside reactions of the crosslinking reagent with water. Konigsberg U.S.Pat. No. 2,500,950 discloses the crosslinking of starch withepoxyhalogen compounds such as epichlorohydrin.

It is preferred that the starch or hydrolyzed starch for use in thepresent invention be crosslinked with epichlorohydrin in a basic aqueousstarch suspension at a temperature and for a period of time such thatthe Brabander viscosity of the suspension is within about 50% to 100% ofthe maximum viscosity. The viscosity will vary by the amount ofcrosslinking and the test conditions, i.e., temperature, concentrations,etc. A viscosity peak indicates maximum crosslinking. When the desiredviscosity is reached, the crosslinking reaction is terminated. ABrabender viscometer is a standard viscometer readily available on theopen market and well known to those skilled in the art.

Generally, the treatment level is from about 0.005% to about 0.1% ofstarch to give a low degree of crosslinking of about one crosslink per200 to 1000 anhydroglucose units. As indicated, the crosslinking may beundertaken before or after the starch is derivatized.

The epichlorohydrin crosslinked starch is then preferably reacted withpropylene oxide to form the hydroxypropyl ether. The reaction ofpropylene oxide and starch is base catalyzed. Aqueous slurry reactionsare generally catalyzed by 0.5 to 1% sodium hydroxide based on the dryweight of starch. Sodium sulfate or sodium chloride may be added to keepthe starch from swelling during reaction with the propylene oxide.Reaction temperatures are generally in the range of from about 37.7° C.to about 51.7° C. (100° to 125° F.). Propylene oxide levels generallyrange from about 1% to about 10% based on the dry weight of the starch.Propylene oxide-starch reactions take approximately 24 hours to completeunder the conditions described and are about 60% efficient with respectto the propylene oxide. It is preferred that the epichlorohydrincrosslinked hydroxypropyl ether contain from about 0.5% to about 5%reacted propylene oxide based on the dry weight of starch or hydrolyzedstarch.

Other methods of preparing epichlorohydrin crosslinked starches andhydroxypropyl starch ethers are well known in the art.

The preferred starch ether derivative as indicated is the hydroxypropylether. Other representative starch derivatives are hydroxyethyl ethers,carboxymethyl ethers, dihydroxypropyl ethers, hydroxyalkyl carboxymethylethers, and cationic starch ethers. The preparation of such starchderivatives is well known in the art.

The particle size distribution of the magnesia bridging agent must besufficient to bridge across and seal the pores in the subterraneanformation contacted by the fluid, all as is well known in the art.Generally, as disclosed in U.S. Pat. No. 4,175,042, incorporated hereinby reference, the particle size range is from about 5 microns to about800 microns with greater than about 5% by weight of the particles beingcoarser than about 44 microns. However, as indicated in Dobson, Jr. etal. U.S. Pat. No. 5,629,271, incorporated herein by reference, theaddition of a supplementary bridging agent having a particle size suchthat at least 90% of the particles thereof are less than 10 microns andthe average particle size is from about 3 to about 5 microns decreasesthe fluid loss of the fluids and reduces the concentration of polymerrequired to impart the desired degree of fluid loss control to thefluids. This in effect increases the concentration of particles lessthan 10 microns diameter in the fluid.

Since the particle size distribution of the bridging agent needed in anywell drilling and servicing operation is related to the size of theopenings in the formations to be bridged and sealed, it is preferred tohave several particulate, sized magnesia products having differentparticle size distributions which can be blended to produce fluidseffective in sealing the formations contacted by the fluids.

The aqueous liquid used to prepare the WDSF of this invention may be anyliquid compatible with the polymeric viscosifier and the polymeric fluidloss control additive used to prepare the WDSF. Thus, the aqueous liquidmay be natural or a synthetic brine having one or more water solublesalts dissolved therein. Exemplary water soluble salts well known in theart are sodium chloride, calcium chloride, potassium chloride, sodiumbromide, calcium bromide, potassium bromide, zinc bromide, sodiumformate, potassium formate, cesium formate, and other water solublesalts as desired. Generally, the concentration of water soluble salts inthe aqueous brine may be any concentration up to saturation in order toprovide the aqueous liquid with the density desired, such as from 8.3ppg (1000 kg/m³) to about 19.2 ppg (2304 kg/m³).

The fluids of this invention are further characterized in Table A. TABLEA Most Operable Preferred Preferred Water Soluble Polymer Viscosifier,1.03-14.3 2.14-11.4 2.85-8.56 kg/m³ Fluid Loss Control Additive, kg/m³ 5.7-42.8  8.5-28.5 11.4-22.8 Magnesia Bridging Agent, kg/m³ 42.8-286  51-228  71-171 Low Shear Rate Viscosity, cp* >10,000 >15,000 >20,000Spurt Loss, ml* <5 <3 <3 30-Minute Fluid Loss, ml* <15 <10 <10*Determined as disclosed hereinafter

The fluids of the invention may be prepared and the method of theinvention practiced, by mixing the aqueous liquid as set forth hereinwith the polymeric viscosifier, the polymer fluid loss control additive,and the bridging agent, and any optional additives as desired.

The fluids of the invention are useful in various petroleum recoveryoperations such as well drilling, including drilling intohydrocarbon-containing formations, completion, workover and the like allas are well known in the art. Specifically the fluids of the inventionare useful in drilling a well wherein the drilling fluid is circulatedwithin a borehole being drilled as drilling proceeds, and in wellcompletion and workover methods wherein a subterranean formation iscontacted with an aqueous fluid to form a bridge and seal on theformation, all as are well known in the art.

The low shear rate viscosity (LSRV) for purposes of this invention isobtained using a Brookfield Model LVTDV-1 viscometer having a number 1or 2 spindle at 0.3 revolutions per minute (shear rate of 0.0636 sec⁻¹).The fluid loss characteristics of the fluids are obtained by a modifiedAPI filtration test. Thus, to an API high temperature filtration cellwith removable end cages is added a 5 micron disk (i.e., an aluminumoxide Aloxite™ ceramic disk having 5 micron pore throats, from 600 to750 md permeability, which is 2.5 inches in diameter and 0.25 inch indepth) saturated with water. The fluid to be tested is poured along theinside edge of the filtration cell. The filtration test is thenconducted for 30 minutes at the desired temperature of 150° F. under apressure differential of 250 pounds per square inch supplied bynitrogen. The spurt loss is measured as the amount of fluid expelledfrom the filtration cell until the flow of fluid is reduced to drops.The fluid loss is measured as the total amount of fluid collected in 30minutes.

The Fann viscosity data is obtained utilizing a Fann 35 viscometer inaccordance with the procedures set forth in API Recommended PracticeRP-13B-1.

The typical particle size distribution of these calcined, particulate,sized agnesia products utilized in the examples to follow is set forthin Table B. The ctivity Index of these products is as follows: MagnesiaA—840 seconds; agnesia B—1410 seconds; Magnesia C—1740 seconds. TABLE BTypical Volume % of Particles Under the Indicated Size Particle Size,microns Magnesia A Magnesia B Magnesia C 3.09  26.81  17.49  10.23 5.03 43.36  27.71  17.53 5.86  50* — — 9.86  76.02  46.72  30.79 10.82 — 50* — 15.12  92.97  63.12  41.67 19.75 — —  50* 20.52  98.88  76.42 51.3 26.2 100  86.15  60.22 35.56 100  95.0  72.66 44 100  98.5  81.357.97 100 100  90.72 106.8 100 100 100*Medium particle size (D₅₀)

The particle size of the magnesia is determined with a MalvernInstruments' MASTERSIZER particle size analyzer. The preferred particlesize of the calcined magnesia has an average particle size (D₅₀) fromabout 5 microns to about 50 microns.

The Activity Index of the calcined magnesia decreases as the particlesize decreases. The Activity Index of the calcined magnesia beforegrinding and sizing for the magnesia samples A, B, and C was greaterthan 40 minutes. Calcined magnesia having a median particle size (D₅₀)of 30, 50 and 150 microns has an Activity Index of 1890, 2940, and 5610seconds, respectively. The preferred calcined magnesia has an ActivityIndex from about 800 seconds to about 3000 seconds.

In order to more completely describe the invention, the followingnon-limiting examples are given. In these examples and thisspecification, the following abbreviations may be used: API=AmericanPetroleum Institute; LSRV=Brookfield low shear rate viscosity at 0.03revolutions per minute, 0.0636 sec⁻¹, in centipoise; sec=second(s);ppg=pounds per gallon; ppb=pounds per 42 gallon barrel; ° C.=degreesCentrigrade; ° F.=degrees Fahrenheit; g=grams; ml=milliliters;min=minutes; cp=centipoise; Pa=pascal; kg/m³=kilograms/cubic meter;rpm=revolutions per minute; in =inches; sq.ft.=square feet; GS=gelstrength.

EXAMPLE 1

Well drilling and servicing fluids were prepared containing 339.5 ml ofa 1200 kg/m³ (10.0 ppg) NaCl brine, and the concentrations of xanthangum, starch derivative A, and Magnesias A, B, and C set forth inTable 1. The initial properties and the properties after static-agingthe fluids for 16 hours at 65.5° C. (150° F.) were determined. The dataobtained is set forth in Table 1. The data indicate the excellentstability of the fluids.

Starch derivative A is available from TBC-Brinadd, Houston, Tex., asBROMA FLA.

EXAMPLE 2

Well drilling and servicing fluids were prepared containing 336 ml of a1200 kg/m³ (10.0 ppg) NaCl brine, 1.25 g xanthan gum, 4.0 g starchderivative B, and the concentrations of Magnesias A, B, and C set forthin Table 2. Starch derivative B is FL-7+available from TBC-Brinadd,Houston, Tex. TABLE 1 Fluid 1-1 1-2 1-3 Xanthan Gum, g 1.25 1.25 1.0Starch Derivative A, g 4.0 5.0 6.0 Magnesia A, g 7.8 7.8 15.6 MagnesiaB, g 7.8 7.8 5.2 Magnesia C, g 10.4 10.4 5.2 Initial Properties PV, cp14 16 16 YP, Pa 11.5 12.96 10.56 10-Sec GS, Pa 4.8 4.8 3.36 10-Min, GS,Pa 6.24 6.72 4.8 LSRV, cp 19,700 26,800 16,600 pH 10.27 10.29 10.22Fluid Spurt Loss, ml 2.5 2.0 2.0 30 min., ml 6.5 6.5 6.0 PropertiesAfter Static Aging at 65.5° C. (150° F.) for 16 Hours PV, cp 14 19 19YP, Pa 9.6 12.96 12.96 10-Sec GS, Pa 3.84 5.28 4.32 10-Min, GS, Pa 5.767.2 6.24 LSRV, cp 19,000 25,800 19,500 pH 10.76 10.95 10.94 Fluid LossSpurt Loss, ml 2.0 2.0 2.0 30 min., ml 8.5 7.0 7.5 Gelation None NoneNone Settling None None None Separation None None None

TABLE 2 Fluid 2-1 2-2 2-3 Xanthan Gum, g 1.25 1.25 1.25 StarchDerivative B, g 4.0 5.0 4.0 Magnesia A, g 9.6 12 4.8 Magnesia B, g 0 04.8 Magnesia C, g 38.4 36 38.4 Properties After Static Aging at 65.5° C.(150° F.) for 16 Hours PV, cp 19 24 20 YP, Pa 13.44 17.28 14.88 10-SecGS, Pa 5.28 6.24 5.76 10-Min, GS, Pa 6.72 7.2 7.2 LSRV, cp 28,100 36,10033,700 pH 10.20 10.60 10.47 Fluid Loss Spurt Loss, ml 2.0 2.0 2.0 30min., ml 11.5 9.5 10.5 Gelation None None None Settling None None NoneSeparation None None None

EXAMPLE 3

A well drilling and servicing fluid was prepared containing 339.5 ml(0.97 bbl equivalent) of a 1440 kg/m³ (12.0 ppg) NaBr brine, 1.25 g ofxanthan gum, 4.0 g of starch derivative B, 7.8 g of Magnesia A, and 18.2g of Magnesia C. The initial properties and properties after hot rolling16 hours at 65.5° C. (150° F.) and cooling to ambient temperature areset forth in Table 3. TABLE 3 INITIAL AFTER HOT ROLLING PV, cp 17 22 YP,Pa 13.44 14.88 10-Sec. GS, Pa 5.76 5.76 10-Min. GS, Pa 7.68 10.08 LSRV,cp 37,800 52,900 pH 9.38 10.27 Fluid Loss Spurt Loss, ml — 2.0 30-Min.,ml — 8.5

EXAMPLE 4

Well drilling and servicing fluids were prepared in a 1200 kg/m³ (10.0ppg) NaCl brine containing 3.57 kg/m³ (1.25 ppb) xanthan gum, 11.4 kg/m³(4.0 ppb) starch derivative A, and a total of 74.2 kg/m³ (26 ppb)magnesia of different particle size distribution as indicated in Table4. The fluids were evaluated for fluid loss control. The datademonstrates that increasing the concentrations of the finer (smaller)bridging particles decreases the fluid loss at 26 ppb total bridgingsolids. TABLE 4 4-1 4-2 4-3 4-4 4-5 Fluid Magnesia A, kg/m³ 7.4 18.522.25 29.7 44.5 Magnesia B, kg/m³ 7.4 18.5 22.25 29.7 14.8 Magnesia C,kg/m³ 59.3 37.1 29.7 14.8 14.8 Fluid Loss Spurt Loss, ml 3.0 3.0 2.0 2.02.0 30-Min., ml 8.0 8.0 6.5 6.5 6.0

EXAMPLE 5

Example 4 was repeated except that the fluids contained a total of 42.8kg/m³ (15 ppg) magnesia bridging solids. TABLE 5 Fluid 5-1 5-2 5-3Magnesia A, kg/m³ 21.4 14.265 12.8 Magnesia B, kg/m³ 10.7 14.265 0Magnesia C, kg/m³ 10.7 14.265 29.95 Fluid Loss Spurt Loss, ml 2.5 2.03.5 30-Min., ml 7.5 6.5 8.5

EXAMPLE 6

Well drilling and servicing fluids were prepared containing 336 ml of a1200 kg/m³ (10.0 ppg) NaCl brine, 1.25 g xanthan gum, 4.0 g of thestarch derivatives indicated in Table 6, and a total of 48 g of magnesiabridging solids as indicated in Table 6. Starch derivative C EMFLOCHCKLV available from TCM Chemicals, Inc. and starch derivative D isEMFLOC SXT available from TCM Chemicals, Inc.

Starch derivative E is DRILSTAR HT available from Chemstar. TABLE 6Fluid 6-1 6-2 6-3 6-4 Starch Derivative A C D E Magnesia A, g 9.6 12 129.6 Magnesia B, g 0 0 0 0 Magnesia C, g 38.4 36 30 38.4 Properties AfterStatic Aging at 150° F. for 16 Hours PV, cp 18 20 35 19 YP, Pa 10.5611.52 49.9 9.6 10-Sec GS, Pa 4.32 3.84 25 3.36 10-Min, GS, Pa 5.76 6.7231.2 4.8 LSRV, cp 20,400 20,700 248,000 13,100 pH 10.35 10.92 10.5210.34 Fluid Loss Spurt Loss, ml 2.0 2.0 2.0 4.5 30 min., ml 10.5 12.012.0 12.5 Gelation None None Slight None Settling None None None NoneSeparation None None None ⅜ in

1. A well drilling and servicing fluid comprising an aqueous liquid, awater soluble polymer viscosifier, a polymeric fluid loss controladditive, and a particulate magnesia bridging agent wherein the magnesiahas an Activity Index greater than about 800 seconds.
 2. The fluid ofclaim 1 wherein the polymer is a biopolymer produced by fermentation ofa carbohydrate source by the action of bacteria or fungi which is anexcellular polysaccharide having a molecular weight in excess of about500,000.
 3. The fluid of claim 2 wherein the polymer is xanthan gum. 4.The fluid of claim 1 wherein the polymeric fluid loss control additiveis selected from the group consisting of pregelatinized starch, starchderivatives, cellulose derivatives, and mixtures thereof.
 5. The fluidof claim 1 wherein the polymeric fluid loss control additive is a starchderivative selected form the group consisting of hydroxyethyl starch,hydroxypropyl starch, hydroxyalkyl carboxymethyl starch, carboxymethylstarch, tertiary aminoalkyl ether derivatives of starch, and theslightly crosslinked derivatives of such derivatized starches, andmixtures thereof.
 6. The fluid of claim 1 wherein the polymeric fluidloss control additive is a hydroxypropyl ether derivative of starchwhich has been slightly crosslinked with epichlorohydrin.
 7. The fluidof claim 1 wherein the polymeric fluid loss control additive is selectedfrom the group consisting of a crosslinked ether derivative of (1) apartially hydrolyzed starch, (2) a partially depolymerized, crosslinkedether derivative of starch, and (3) mixtures thereof.
 8. The fluid ofclaim 3 wherein the polymeric fluid loss control additive is ahydroxypropyl ether derivative of starch which has been slightlycrosslinked with epichlorohydrin.
 9. The fluid of claim 3 wherein thepolymeric fluid loss control additive is selected from the groupconsisting of a crosslinked ether derivative of (1) a partiallyhydrolyzed starch, (2) a partially depolymerized, crosslinked etherderivative of starch, and (3) mixtures thereof.
 10. The fluid of claim 1wherein the Activity Index is from about 800 seconds to about 3000seconds.
 11. The fluid of claim 10 wherein the polymer viscosifier isxanthan gum and wherein the polymeric fluid loss control additive isselected from the group consisting of a crosslinked ether derivative of(1) a partially hydrolyzed starch, (2) a partially depolymerized,crosslinked ether derivative of starch, and (3) mixtures thereof. 12.The process of drilling a well wherein the fluid of claim 1 iscirculated within a borehole being drilled as drilling proceeds.
 13. Theprocess of drilling a well wherein the fluid of claim 2 is circulatedwithin a borehole being drilled as drilling proceeds.
 14. The process ofdrilling a well wherein the fluid of claim 3 is circulated within aborehole being drilled as drilling proceeds.
 15. The process of drillinga well wherein the fluid of claim 4 is circulated within a boreholebeing drilled as drilling proceeds.
 16. The process of drilling a wellwherein the fluid of claim 5 is circulated within a borehole beingdrilled as drilling proceeds.
 17. The process of drilling a well whereinthe fluid of claim 6 is circulated within a borehole being drilled asdrilling proceeds.
 18. The process of drilling a well wherein the fluidof claim 7 is circulated within a borehole being drilled as drillingproceeds.
 19. The process of drilling a well wherein the fluid of claim8 is circulated within a borehole being drilled as drilling proceeds.20. The process of drilling a well wherein the fluid of claim 9 iscirculated within a borehole being drilled as drilling proceeds.
 21. Theprocess of drilling a well wherein the fluid of claim 10 is circulatedwithin a borehole being drilled as drilling proceeds.
 22. The process ofdrilling a well wherein the fluid of claim 11 is circulated within aborehole being drilled as drilling proceeds.
 23. The process ofcompleting or working over a well wherein a subterranean formation iscontacted with the fluid of claim
 1. 24. The process of completing orworking over a well wherein a subterranean formation is contacted withthe fluid of claim
 2. 25. The process of completing or working over awell wherein a subterranean formation is contacted with the fluid ofclaim
 3. 26. The process of completing or working over a well wherein asubterranean formation is contacted with the fluid of claim
 4. 27. Theprocess of completing or working over a well wherein a subterraneanformation is contacted with the fluid of claim
 5. 28. The process ofcompleting or working over a well wherein a subterranean formation iscontacted with the fluid of claim
 6. 29. The process of completing orworking over a well wherein a subterranean formation is contacted withthe fluid of claim
 7. 30. The process of completing or working over awell wherein a subterranean formation is contacted with the fluid ofclaim
 8. 31. The process of completing or working over a well wherein asubterranean formation is contacted with the fluid of claim
 9. 32. Theprocess of completing or working over a well wherein a subterraneanformation is contacted with the fluid of claim
 10. 33. The process ofcompleting or working over a well wherein a subterranean formation iscontacted with the fluid of claim 11.